The present invention relates to high pressure water injection wells for secondary oil recovery and, more particularly, to a process and apparatus for efficiently treating high pressure injection wells to eliminate or minimize excessive material build-up and corrosion within the water injection lines.
The oil industry uses a variety of design techniques to maximize the recovery of oil from any particular oil formation. One of the methods so used is the injection of water under high pressure at a point removed from the site of the oil removal. Large amounts of water are injected under high pressure into the oil-producing sands. The injected water is removed at the oil well site along with the resident oil. Such treatment typically requires up to twenty parts of injection water per part oil recovered. Given this large amount of required water, oil producers utilize the nearest suitable source of water, which is often the water produced with the oil. Generally, such produced water contains a wide variety of impurities such as sulfur and sulfur compounds, and these impurities are often reinjected in the water injection well with the water.
The constant high volume flow of sulfur-containing and sulfur compound-containing water and the warm, incubator-like environment of oil field water treatment systems encourages the uncontrolled growth of bacteria--the source of many costly problems. The bacteria feed on the sulfur and the sulfur compounds thereby forming hydrogen sulfide and metallic sulfides. Bacterial growth, if left unchecked, causes, in addition to the formation of hydrogen sulfide, a toxic and corrosive gas that eats through piping in water and vapor recovery systems, the accumulation of gummy biomass that adheres to surfaces and filter media and substantially reduces equipment efficiency, and the formation of abrasive iron sulfide that wears injection pumps, decreases injectivity, fouls flow lines and causes corrosion; all of which increase operating costs and lower oil production. The build-up in the pipeline constricts the flow of water with the result that less oil is produced. If the water injection pipelines are not cleaned out periodically, they can become entirely obstructed.
Under the present state of the art, the commonly accepted procedure for cleaning out such water injection casings is to inject a mixture of hydrochloric acid and hydrofluoric acid into the water injection well. A typical mixture, commonly referred to as mud acid, contains 30% hydrochloric acid and 5% hydrofluoric acid. The hydrofluoric acid solubilizes the silicates and other sources of build-up, and the hydrochloric acid, by keeping the pH of the system low, keeps the material solubilized so that it can be washed out of the water injection well. This prior art method suffers from several problems. First, the hydrochloric/hydrofluoric mixture is highly corrosive and will corrode the metal walls of the water injection wells. In addition, such a mixture has little or no effect on any bacteria that may have built up. Such bacteria is often the primary obstructor. Finally, this method of clean-out is relatively expensive.
Attempts to control the growth of bacteria usually involves the use of biocides. The conventional biocides such as glutaraldehyde, acrolein, and quaternary amines are non-oxidizing compounds. They effectively kill bacteria by altering the permeability of the cell membrane of the microorganisms, thereby interfering with their vital life processes. The application of these products, however, does nothing for the plugging, fouling, deposits, and corrosion that have already been caused by the bacteria and bacterial by-products.
The present invention involves the use of the compound chlorine dioxide as a bactericide. Chlorine dioxide not only very effectively kills the bacteria but also oxidizes the hydrogen sulfide and metallic sulfides to relatively harmless and soluble sulfates. Typically, chlorine dioxide is produced in situ by reacting a precursor, such as sodium chlorate, with a reducing agent, such as sodium chloride, at very low pHs to produce chlorine dioxide. The method of producing chlorine dioxide forms no part of the present invention and any of the several conventional procedures can be employed. For a good review of the chemistry, physical properties, and use of chlorine dioxide, see Masschelein, W. J., "Chlorine Dioxide--Chemistry and Environmental Impact of Oxychlorine Compounds," Ann Arbor Science Publishers, Inc. (1979).
A major disadvantage of using chlorine dioxide is that it is inherently explosive; consequently, extensive controls on the reaction conditions and on the reaction effluent are required when using this compound. In the gaseous state, chlorine dioxide is explosive at concentrations above about ten percent in air. Given the explosive tendencies of chlorine dioxide, measures must be taken to prevent the occurrence of explosions, particularly in the vicinity of highly flammable hydrocarbons which are always present in oil fields. The present invention provides a method of using chlorine dioxide to minimize the growth of sulfur-feeding bacteria and the fouling caused by the waste products of such bacteria without encountering the explosive hazards usually attending the use of chlorine dioxide.
The present invention makes use of the fact that aqueous solutions of chlorine dioxide are not explosive, provided that there is no opportunity for chlorine dioxide to accumulate in any vapor space above the chlorine dioxide solution. This is prevented by maintaining the aqueous solution under a moderately high pressure in a system that does not contain vapor spaces. The high pressure system enables the water to dissolve more chlorine dioxide and also permits the aqueous solution to be injected into a water injection stream, which is generally maintained at pressures of 1000 psig or more.
Attempts to treat high pressure water injection wells with chlorine dioxide have been frustrated because chlorine dioxide and the strong acids usually used in the generation of chlorine dioxide are highly corrosive and severely attack most materials, including stainless steel. Stainless steel tubing has been tried, but it failed after a short period of time because of corrosion.
In low pressure chlorine dioxide treatments, the corrosivity problem can be avoided by the use of pipes and fittings made from fiberglass or plastic materials such as polyvinyl chloride or polyvinylidene fluoride. However, these materials are not always suitable for high pressure applications because tubing and fittings would have to be of considerable thickness. For instance, to provide adequate strength to withstand the high pressures required to inject chlorine dioxide solution into a high pressure injection water pipeline, the thickness of appropriate plastic tubing to carry the chlorine dioxide into the pipeline would prohibitively decrease the flow of injection water in the pipeline.
One family of metal alloys which are resistant to the corrosive effects of chlorine dioxide is nickel-chromium-molybdenum-colbalt alloy. These alloys are very costly, however, and no known attempts have been made to use them in high pressure chlorine dioxide applications.